Pumping system

ABSTRACT

Methods and systems for pumping a production fluid from a production zone to a collection point are described herein. The methods generally include disposing a tubing in the production zone of a wellbore; pumping the production fluid from the production zone through a first stage of a pumping system to achieve an inter-stage pressure sufficient for entry into a second stage; and pumping the production fluid at the inter-stage pressure through a second stage of the pumping system to achieve a lifting pressure sufficient to lift the production fluid to a collection point, wherein the second stage includes a jet pump.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Invention

The present invention generally relates to pumping systems. Inparticular, embodiments of the present invention relate to pumpingsystems for use within artificial lift systems.

2. Related Art

This section introduces information from the art that may be related toor provide context for some aspects of the techniques described hereinand/or claimed below. This information is background facilitating abetter understanding of that which is disclosed herein. This is adiscussion of “related” art. That such art is related in no way impliesthat it is also “prior” art. The related art may or may not be priorart. The discussion is to be read in this light, and not as admissionsof prior art.

A variety of systems are known for producing fluids from subterraneangeological formations. In formations providing sufficient pressure toforce the fluids to the earth's surface, the fluids may be collected andprocessed without the use of artificial lifting systems. Where, however,well pressures are insufficient to raise fluids to the collection point,artificial means are often employed, which include pumping systems.

The particular configurations of an artificial lift pumping system mayvary widely depending upon the well conditions, the geologicalformations present, and the desired completion approach. In general,however, such systems often include an electric motor driven by powersupplied from the earth's surface. The motor is coupled to a pump (oftenreferred to as a down-hole pump), which draws production fluids from aproduction zone and imparts sufficient head to force the fluids to thecollection point. Such systems may include additional componentsespecially adapted for the particular production fluids or mix offluids, including gas/oil separators, oil/water separators, sand controldevices and so forth.

One such artificial lift pumping system includes a centrifugal pump,such as an electrical submersible pumps (ESP), often disposed below thelevel of fluids. Centrifugal pumps generally include a motor section, apump section and a motor protector to seal the clean motor oil fromproduction fluids, and are deployed in a wellbore where they receivepower via an electrical cable. Centrifugal pumps are generally capableof generating a large pressure boost sufficient to lift productionfluids, even in ultra-deep water, low pressure subsea formations.However, centrifugal pumps are susceptible to free gas impact(interference when gas bubbles/free gas is present at the intake of thepump).

Furthermore, centrifugal pumps are sensitive to sands and other abrasivesolids that may be present in the production fluid. The amount of sandwhich is produced from a well depends on characteristics of theformation and various methods are used to control sand production.However, it is common for some amount of sand or abrasive solids to bepresent in the production fluid. ESPs are particular sensitive to sandpresence due to the nature of their internal components.

In addition, problems can arise when the pump is shut down after aperiod of pumping fluid up production tubing to the collection point. Onpump shutdown, flow ceases very quickly as the fluid levels in thewellbore and the annulus equalize. Gravity acting on the sand particlespresent in the column of fluid above the pump causes the sand and anyother solids to fall back towards the pump. Due to the complexconfiguration of the interior features of the pump, there is no directpath for the sand to pass through the pump and therefore it tends tosettle on the internal working components of the pump. This can causethe pump to become plugged or cause damage, leading to premature failureof the pump.

The present invention is directed to resolving, or at least reducing,one or all of the problems mentioned above.

SUMMARY

Various embodiments of the present invention include methods of pumpinga production fluid from a production zone to a collection point. Onespecific, non-limiting embodiment of the methods include disposing atubing in the production zone of a wellbore; pumping the productionfluid from the production zone through a first stage of a pumping systemto achieve an inter-stage pressure sufficient for entry into a secondstage; and pumping the production fluid at the inter-stage pressurethrough a second stage of the pumping system to achieve a liftingpressure sufficient to lift the production fluid to a collection point,the second stage comprises a jet pump and wherein the first stage pumpis selected and operated so that a first stage dynamic head is at least110% of the total dynamic head of the first stage pump absent the secondstage.

One or more embodiments include the method of the preceding paragraph,wherein the jet pump is selected and operated so that the first stagepump is choked and operating in its recommended operating range.

One or more embodiments include the method of any preceding paragraph,wherein the first stage includes a first stage pump that varies from thejet pump.

One or more embodiments include the method of any preceding paragraph,wherein the first stage pump is selected from centrifugal pumps, rotarypumps and combinations thereof.

One or more specific non-limiting embodiments of the invention includestaged pumping systems for producing a fluid from a subterraneangeological formation. The pumping system is disposed within a well viatubing and, in one embodiment, includes a centrifugal pump assemblycomprising a motor section and a centrifugal pump section, wherein thecentrifugal pump, in operation, transfers the production fluid from thesubterranean geological formation; and a jet pump assembly including anozzle, suction chamber and check valve disposed below the nozzle,wherein the jet pump assembly, in operation, receives the productionfluid from the centrifugal pump assembly and lifts the production fluidto a collection point; and a single seat, wherein the seat, in operationsecures the jet pump assembly thereon.

One or more embodiments include the system of the preceding paragraph,wherein the subterranean geological formation is a subsea formation.

One or more embodiments include the system of any preceding paragraph,wherein the centrifugal pump assembly, in operation, provides a totaldynamic head of at least 110% of the total dynamic head of thecentrifugal pump assembly absent the second stage.

One or more embodiments include the system of any preceding paragraph,wherein the pumping system is part of a lift system.

One or more embodiments include the lift system of the precedingparagraph and further including a production packer disposed within anannulus above the jet pump assembly.

One or more embodiments include the lift system of any precedingparagraph, wherein the production fluid includes gas and liquid and thelift system further includes a production packer disposed within anannulus below the jet pump assembly.

One or more embodiments include the pumping system of any precedingparagraph and further include a gas separator, a gas handling device orcombinations thereof.

One or more embodiments include the system of the preceding paragraph,wherein the gas separator includes a tandem gas separator.

One or more embodiments include the system of any preceding paragraphand further include a fallback preventer disposed above the jet pumpassembly.

One or more embodiments include the system of the preceding paragraph,wherein the fallback preventer includes an automatic shutoff valve.

In one or more specific, non-limiting embodiments, the staged pumpingsystem includes a centrifugal pump assembly including a motor sectionand a centrifugal pump section, wherein the centrifugal pump, inoperation, transfers the production fluid from the subterraneangeological formation; and a jet pump assembly including a nozzle,suction chamber and check valve disposed below the nozzle, wherein thejet pump assembly, in operation, receives the production fluid from thecentrifugal pump assembly and lifts the production fluid to a collectionpoint; and wherein the centrifugal pump assembly is, in operation,controlled by a variable speed drive operated in current mode.

In other specific, non-limiting embodiments, the staged pumping system afirst stage pump assembly, wherein the first stage pump assembly, inoperation, transfers the production fluid from the subterraneangeological formation; and a jet pump assembly including a nozzle,suction chamber and check valve disposed below the nozzle, wherein thejet pump assembly, in operation, receives the production fluid from thecentrifugal pump assembly and lifts the production fluid to a collectionpoint; and a fallback preventer disposed above the jet pump assembly.

One or more embodiments included the system of the preceding claim,wherein the first stage pump assembly is selected from rotary pumps,centrifugal pumps and combinations thereof.

One or more embodiments include the system of any preceding claim,wherein the fallback preventer includes an automatic diverter valve.

One or more embodiments include the system of any preceding claim,wherein the pumping system is part of an artificial lift system andwherein the lift system further includes a production packer disposedwithin an annulus above the jet pump assembly.

The above paragraphs present a simplified summary of the presentlydisclosed subject matter in order to provide a basic understanding ofsome aspects thereof. The summary is not an exhaustive overview, nor isit intended to identify key or critical elements to delineate the scopeof the subject matter claimed below. Its sole purpose is to present someconcepts in a simplified form as a prelude to the more detaileddescription set forth below.

BRIEF DESCRIPTION OF THE DRAWINGS

The claimed subject matter may be understood by reference to thefollowing description taken in conjunction with the accompanyingdrawings, in which like reference numerals identify like elements, andin which:

FIG. 1 illustrates a non-limiting embodiment of a pumping system.

FIG. 2 illustrates a non-limiting embodiment of a jet pump assembly.

FIG. 3 illustrates a non-limiting embodiment of an artificial liftsystem.

While the claimed subject matter is susceptible to various modificationsand alternative forms, the drawings illustrate specific embodimentsherein described in detail by way of example. It should be understood,however, that the description herein of specific embodiments is notintended to limit the claimed subject matter to the particular formsdisclosed, but on the contrary, the intention is to cover allmodifications, equivalents, and alternatives falling within the spiritand scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

Illustrative embodiments of the subject matter claimed below will now bedisclosed. In the interest of clarity, not all features of an actualimplementation are described in this specification. It will beappreciated that in the development of any such actual embodiment,numerous implementation-specific decisions must be made to achieve thedevelopers' specific goals, such as compliance with system-related andbusiness-related constraints, which will vary from one implementation toanother. Moreover, it will be appreciated that such a developmenteffort, even if complex and time-consuming, would be a routineundertaking for those of ordinary skill in the art having the benefit ofthis disclosure.

In the description below, various ranges and/or numerical limitationsmay be expressly stated below. It should be recognized that unlessstated otherwise, it is intended that endpoints are to beinterchangeable. Further, any ranges include iterative ranges of likemagnitude falling within the expressly stated ranges or limitations.

In the specification and appended claims, the terms “connect”,“connection”, “connected”, “in connection with” and “connecting” areused to mean “in direct connection with” or “in connection with viaanother element”, and the term “set” is used to mean “one element” or“more than one element”. As used herein, the terms “up” and “down”,“upper” and “lower”, “upwardly” and “downwardly”, “upstream” and“downstream”, “above” and “below” and other like terms indicatingrelative positions above or below a given point or element are used inthis description to more clearly describe some embodiments of theinvention. However, when applied to equipment and methods for use inwells that are deviated or horizontal, such terms may refer to a left toright, right to left or other relationship as appropriate.

Furthermore, various modifications may be made within the scope of theinvention as herein intended, and embodiments of the invention mayinclude combinations of features other than those expressly claimed. Inparticular, flow arrangements other than those expressly describedherein are within the scope of the invention.

A completed well generally includes a main wellbore that is lined andsupported by one or more casing strings and production tubing. It isnoted that the wellbore may be uncased in accordance with otherembodiments of the invention. The space between the production tubingand casing is called the annulus. A production packer sometimes sealsthe annulus above the production zone. As used herein, the term “above”refers to a location between the production zone and the collectionpoint. The casing, when present, may be perforated adjacent to theproduction zone to allow entrance of fluid into the wellbore and/or theproduction tubing may extend into the open hole. The production fluidmay flow into a valve, such as a circulation valve of the productiontubing and be communicated to the surface of the well via the productiontubing's central passageway (e.g., the wellbore).

In one or more embodiments, a pumping system is provided for liftingproduction fluid (e.g., oil, gas, water, helium or other fluid, or acombination thereof) from a well. The pumping system may be includedwithin an artificial lift system, for example.

The pumping system generally includes staged pumping of the productionfluids. For example, the production fluid is pumped through a firststage to achieve an inter-stage pressure sufficient for entry into asecond stage to achieve a lifting pressure sufficient to lift the fluidto the collection point. Accordingly, the pumping system generallyincludes a first stage pump and a second stage pump. The first stagepump includes any pump capable of lifting the fluid as required. Forexample, the first stage pump may include a rotary pump, such as apositive displacement pump (including progressing cavity pumps), acentrifugal pump, such as an ESP or combinations thereof. The secondstage pump generally includes one or more jet pumps.

Jet pumps generally operate by forcing a pressurized fluid through anozzle, where it is converted into a high velocity stream. This highvelocity stream decreases the pressure in a suction chamber, creating apartial vacuum that draws the suction material into the chamber where itis entrained. Once the suction stream is drawn in, shear causesintermixing and pumping the fluid out of a discharge dispelled at apressure greater than that of the suction stream. Jet pumps are able totolerate a wide range of operating conditions, including sand laden orabrasive fluids.

In one or more embodiments, the jet pump is selected so that the firststage pump is choked and operating in its recommended operating range.Such selection/operation reduces the load on the first stage pump,thereby extending its operating life.

In one or more embodiments, the tubing includes a seat for securingcomponents of the pumping system therein. For example, the seat maysecure the jet pump assembly. In one or more embodiments, the seat isdisposed above a first stage total dynamic head. In another embodiment,the seat is disposed, during operation, below a first stage totaldynamic head. As used herein, the “first stage dynamic head” refers tothe total equivalent height that a fluid is to be pumped in the firststage, taking into account friction losses in the pipe. It is to benoted that first stage dynamic head can be referred to interchangeablyherein and is approximately equal to the discharge pressure of the firststage pump. In one or more embodiments, the system is absent a secondseat. The jet pump may be run in and out of the well with the help ofwire line tools (i.e., the jet pump is “wireline retrievable”).

In one or more embodiments, the first stage pump is selected andoperated so that the first stage dynamic head within the pumping systemis at least 110%, or greater than 110%, or at least 120%, or at least150%, or at least 175% or at least 200% of the total dynamic head of thefirst stage pump absent the second stage (i.e., when run in a standaloneconfiguration), for example.

In one or more embodiments, the first stage pump is controlled by avariable speed drive (VSD) having i-mode (i.e., current mode) adapted toautomatically increase frequency for a short period of time, resultingin a higher ejection coefficient of the jet pump, thereby preventingfirst stage pump gas lock. For example, when operating in current mode,when gas enters the first stage pump, the drive senses the loweramperage, speeds up to maintain amperage and compress the gas to move itthrough the first stage pump. When passed, the drive will slow back downto maintain a desired amperage, thereby improving efficiency andreducing shut downs.

Often, the production fluid has a liquid component and a gas component(e.g., the production fluid may include any amount of gas, such as atleast 50 scf/bbl, or at least 100 scf/bbl). In such cases, the firststage flow pump may include a mixed flow pump. The mixed flow pumpboosts the pressure of the input production fluid to a particular levelto compress or move a sufficient volume of the liberated gas componentinto solution such that the production fluid may be pumped by thesubsequently disposed jet pump. The acceptable gas to liquid ratio mayvary depending on the characteristics of the jet pump. Once theproduction fluid is pressurized to a sufficient level, the productionfluid is fed into the jet pump. The jet pump will further boost thepressure of the production fluid to a sufficient level to facilitateartificial lift of the fluid to the surface or to another collectionpoint.

The pumping system may further utilize a gas separator. In one or moreembodiments, the gas separator is disposed within the first stage pumpassembly prior to the pump section. In operation, the production fluidincluding mixtures of gas and liquid (oil/gas or water/oil/gas) entersthe gas separator. Free gas is then separated in the gas separator fromthe liquid and discharged into the annulus, while the first stage pumppumps the liquid to the nozzle of the jet pump apparatus. It should benoted that the liquid may contain some gas, but the reduction of gasallows the fluid to be better produced with the first stage pump. Inalternative embodiments, the gas separator may be disposed elsewherewithin the pumping system and/or the artificial lift system.

The gas separator may have a variety of designs depending on thespecific application, environment, and types of fluids to be produced.When the gas content of a production fluid is sufficiently high to causerisk of “gas lock” in the first stage pump, at least some of the gas isremoved to create a liquid component with lower gas content. Gas contentin the production fluid also can reduce the hydraulic efficiency of thefirst stage pump. Accordingly, the gas separator may have a variety ofdesigns to remove this excess gas. By way of non-limiting example, thegas separator may be a natural separator, a vortex separator, a reverseflow gas separator, a centrifugal gas separator, a tandem rotary gasseparator or combinations thereof, for example.

The pumping system may alternatively, or in combination with the gasseparator, include a gas handling device capable of conditioning theproduction fluid prior to passing through the first stage pump.

In accordance with one or more embodiments, the fluid that is receivedfrom the production zone may be produced from various perforatedproduction zones of a horizontal or deviated wellbore. Depending on theparticular embodiment of the invention, each production zone may beestablished between packers that form annular seals.

In one or more embodiments, the artificial lift system includes one ormore fallback preventers. The fallback preventer is generally disposedabove the jet pump assembly (herein referring to a location between thejet pump assembly and the collection point).

The fallback preventer may include any apparatus capable of preventingdebris fallback within the wellbore. However, it is to be noted that thefallback preventer is typically capable of allowing debris to pass therethrough towards the surface of the well but prevents debris from fallingback downward through the wellbore, such as upon pump shut-down. Forexample, the fallback preventer may include a valve. The valve functionsto divert flow in the production tubing and is operable to be movedbetween an open position and a closed position.

In one or more embodiments, the valve is a check valve. In otherspecific embodiments, the valve is an auto shutoff valve (i.e., thevalve closes automatically upon fluid flow interruption). On pumpstart-up, the auto shutoff valve automatically operates to close portsto the annulus and pumped production commences to collection point. Uponpump shut-down, fluid within the production tubing exhaust into theannulus. Communication to the pumping system is blocked preventingsolids from falling back towards the pumping system. When the pumpingsystem is restarted, the auto shutoff valve automatically operates toclose ports to annulus and normal production resumes. As with the jetpump, the fallback preventer may be run in and out of the well with thehelp of wire line tools (i.e., the fallback preventer is “wirelineretrievable”).

FIG. 1 illustrates a specific, non-limiting embodiment of the pumpingsystem (100) disposed within a well. The pumping system (100) includes acentrifugal pump assembly (102) adapted to receive a production fluiddisposed within a production zone of a geological formation (112). Thecentrifugal pump assembly (102) is in turn operably connected to a jetpump assembly (104) via production tubing (106).

The centrifugal pump assembly (102) generally includes a pump section(103) and a motor (105) with a seal section (not shown). The centrifugalpump assembly (102) optionally includes a gas separator (107).

The pumping system (100) further includes a seat (108) adapted toreceive the jet pump assembly (104). The seat includes bypass channel(109) to communicate fluid between the jet pump assembly (104) and theannulus (110).

FIG. 2 further illustrates a specific, non-limiting embodiment of thejet pump assembly (200). The jet pump assembly (200) is fitted with acheck valve (202) disposed below the jet nozzle (204). A system ofbypass channels (203, 205, 109—see, FIG. 1) connects the space (207)under the check valve (202) and the suction chamber (206) of the jetpump assembly (200) and the space (209) under the jet nozzle (204) withthe production tubing (106) connected to the centrifugal pump assembly(102)—see, FIG. 1.

The jet pump assembly (200) further includes a mixing chamber (208), adiffuser (210), a discharge head (212), sealing elements (211, 213) andis fitted with a retaining clamp (215) and shear ring (217) for securingin the seat (108—see, FIG. 1). The jet pump assembly 200 may optionallybe fitted with a screen (214) to protect the nozzle (204) from pluggingwith solids.

FIG. 3 further illustrates an embodiment of an artificial lift system(300) including a fallback preventer (304) disposed within the tubingabove the jet pump assembly (104). The fallback preventer (304) isfurther disposed below a production packer (302). It is to be noted thatin FIG. 3, the fallback preventer (300) as well as the jet pump assembly(104) is disposed below the production packer (302). However, in wellswith having gas present within the production fluid, production can belimited by gas interference in the pumping system, and particularly inthe jet pump assembly (104). Accordingly, it is within the scope of theembodiments described herein to have an artificial lift system whereinthe jet pump assembly (and possibly the fallback preventer) is disposedabove the production packer.

It is noted that the wells that depicted in the figures are exemplary innature, in that the pumping system and associated control techniquesthat are disclosed herein, may likewise be applied in other wells. Thusmany variations are contemplated and are within the scope of theappended claims.

Further, while the centrifugal pump assembly (102) and the jet pumpassembly (104) are illustrated as single pumps, it is contemplated thatany number of pumps may be employed with or without standby, backup, orreserve pumps.

With reference again to the Figures, a specific, non-limiting embodimentof the present invention includes an operation for providing a pumpingsystem in a subsea environment. The pumping system is formed byconnecting at least one first stage pump assembly with at least one jetpump assembly. The pumping system may be formed at the surface anddeployed subsea, or deployed as disconnected components and assembledsubsea. Once deployed and connected to an inflow of production fluid,the pumping system imparts flow energy to the production fluid togenerate an energized outlet hydrocarbon flow via an export line to atarget destination. In some embodiments, a power hub is electricallyconnected to the pump system to route electrical energy to the pumps viajumpers or cables. A power umbilical may be provided (e.g., by remoteoperated vehicle or other remote mechanism) to electrically connect thepower hub to an electrical energy source located on the surface, theseabed, subsea or down-hole, for example.

Embodiments of the invention described herein improve the reliability ofthe pumping system. For example, the embodiments described herein arecapable of reliable operation in high gas environments, sandy wellenvironments and combinations thereof.

CLOSING OF THE DETAILED DESCRIPTION

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Note,however, that not all embodiments will necessarily attain all the endsnoted or manifest all the advantages mentioned. Furthermore, differentembodiments will do so to different degrees to the extent they do atall. The particular embodiments disclosed above are illustrative only,as the present invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention.

The invention illustratively disclosed herein suitably may be practicedin the absence of any element that is not specifically disclosed hereinand/or any optional element disclosed herein. While compositions andmethods are described in terms of “comprising,” “containing,” or“including” various components or steps, the compositions and methodscan also “consist essentially of” or “consist of” the various componentsand steps. All numbers and ranges disclosed above may vary by someamount. Whenever a numerical range with a lower limit and an upper limitis disclosed, any number and any included range falling within the rangeare specifically disclosed. In particular, every range of values (of theform, “from about a to about b,” or, equivalently, “from approximately ato b,” or, equivalently, “from approximately a-b”) disclosed herein isto be understood to set forth every number and range encompassed withinthe broader range of values.

This concludes the detailed description. The particular embodimentsdisclosed above are illustrative only, as the invention may be modifiedand practiced in different but equivalent manners apparent to thoseskilled in the art having the benefit of the teachings herein.Furthermore, no limitations are intended to the details of constructionor design herein shown, other than as described in the claims below. Itis therefore evident that the particular embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the invention. Accordingly, the protection soughtherein is as set forth in the claims below.

What is claimed is:
 1. A method of pumping a production fluid from aproduction zone to a collection point comprising: disposing a tubing inthe production zone of a wellbore; pumping the production fluid from theproduction zone through a first stage of a pumping system to achieve aninter-stage pressure sufficient for entry into a second stage; andpumping the production fluid at the inter-stage pressure through asecond stage of the pumping system to achieve a lifting pressuresufficient to lift the production fluid to a collection point, thesecond stage comprises a jet pump and wherein the first stage pump isselected and operated so that a first stage dynamic head is at least110% of the total dynamic head of the first stage pump absent the secondstage.
 2. The method of claim 1, wherein the jet pump is selected andoperated so that the first stage pump is choked and operating in itsrecommended operating range.
 3. The method of claim 1, wherein the firststage comprises a first stage pump that varies from the jet pump.
 4. Themethod of claim 1, wherein the first stage pump is selected fromcentrifugal pumps, rotary pumps and combinations thereof.
 5. A stagedpumping system for producing a fluid from a subterranean geologicalformation, wherein the pumping system is disposed within a well viatubing and wherein the pumping system comprises: a centrifugal pumpassembly comprising a motor section and a centrifugal pump section,wherein the centrifugal pump, in operation, transfers the productionfluid from the subterranean geological formation; and a jet pumpassembly comprising a nozzle, suction chamber and check valve disposedbelow the nozzle, wherein the jet pump assembly, in operation, receivesthe production fluid from the centrifugal pump assembly and lifts theproduction fluid to a collection point; and a single seat, wherein theseat, in operation secures the jet pump assembly thereon.
 6. The pumpingsystem of claim 5, wherein the subterranean geological formation is asubsea formation.
 7. The pumping system of claim 5, wherein thecentrifugal pump assembly, in operation, provides a total dynamic headof at least 110% of the total dynamic head of the centrifugal pumpassembly absent the second stage.
 8. The pumping system of claim 5,wherein the pumping system is part of a lift system.
 9. The lift systemof claim 8 further comprising a production packer disposed within anannulus above the jet pump assembly.
 10. The lift system of claim 8,wherein the production fluid comprises gas and liquid and the liftsystem further comprises a production packer disposed within an annulusbelow the jet pump assembly.
 12. The pumping system of claim 5, whereinthe pumping system further comprises a gas separator, a gas handlingdevice or combinations thereof.
 13. The pumping system of claim 5,wherein the pumping system further comprises a tandem gas separator. 14.The pumping system of claim 5 further comprising a fallback preventerdisposed above the jet pump assembly.
 15. The pumping system of claim14, wherein the fallback preventer comprises an automatic shutoff valve.16. A staged pumping system for producing a fluid from a subterraneangeological formation, wherein the pumping system is disposed within awell via tubing and wherein the pumping system comprises: a centrifugalpump assembly comprising a motor section and a centrifugal pump section,wherein the centrifugal pump, in operation, transfers the productionfluid from the subterranean geological formation; and a jet pumpassembly comprising a nozzle, suction chamber and check valve disposedbelow the nozzle, wherein the jet pump assembly, in operation, receivesthe production fluid from the centrifugal pump assembly and lifts theproduction fluid to a collection point; and wherein the centrifugal pumpassembly is, in operation, controlled by a variable speed drive operatedin current mode.
 17. A staged pumping system for producing a fluid froma subterranean geological formation, wherein the pumping system isdisposed within a well via tubing and wherein the pumping systemcomprises: a first stage pump assembly, wherein the first stage pumpassembly, in operation, transfers the production fluid from thesubterranean geological formation; and a jet pump assembly comprising anozzle, suction chamber and check valve disposed below the nozzle,wherein the jet pump assembly, in operation, receives the productionfluid from the centrifugal pump assembly and lifts the production fluidto a collection point; and a fallback preventer disposed above the jetpump assembly.
 18. The pumping system of claim 17, wherein the firststage pump assembly is selected from rotary pumps, centrifugal pumps andcombinations thereof.
 19. The pumping system of claim 17, wherein thefallback preventer comprises an automatic diverter valve.
 20. Thepumping system of claim 17, wherein the pumping system is part of anartificial lift system and wherein the lift system further comprises aproduction packer disposed within an annulus above the jet pumpassembly.